Apparatus, compositions, and methods of breaking fracturing fluids

ABSTRACT

Apparatus and compositions for reducing the viscosity of a gelled fluid is provided. In one embodiment, a viscosity reducing microbe is disposed in a capsule and added to the gelled fluid. The gelled fluid may include a thickening agent adapted to increase its viscosity. Upon release from the capsule, the microbe begins to digest the thickening agent in the gelled fluid and/or releases enzymes that that breakdown the thickening agent.

RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. patentapplication Ser. No. 12/116,072, filed 6 May 2008 (May 6, 2008), claimspriority to and the benefit of U.S. Provisional Patent Application Ser.No. 60/917,598 filed 11 May 2007 (May 11, 2007).

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to apparatus and methods of breakingfracturing fluids.

More particularly, the present invention relates to apparatus andmethods of breaking fracturing fluids, where the method includes thatstep of supplying a composition to a fracturing fluid prior to or afterinitial fracturing, where the composition includes a microbial agentcapable of digesting or converting a gelled component of the fracturingfluid into low molecular components resulting in a “breaking” of theviscosity of the fracturing fluid over a set and controllable period oftime and to compositions and methods for making the compositions.

2. Description of the Related Art

Most wells are hydraulically fractured to increase flow. The rheologicalrequirements of a fracturing fluid are highly constraining. Toadequately propagate fractures in the subterranean formation, thefracturing fluid is designed to have properties such as body, viscosity,etc. sufficient to form fractures in the formation without leakingexcessively into the formation, when the fracturing fluid is forced intothe formation at elevated pressures. Also, a fracturing fluid isdesigned to have the capability to transport and deposit large volumesof proppant into the fractures or cracks in the formation formed duringfracturing. After the fracturing operation is complete and pressure onthe fluid is released, the fracturing fluid is designed to readily flowback into the well and not leave significant residues in the fracturesthat impair permeability of the formation and conductivity of fluidsinto and out of the fractures. Finally, a fracturing fluid is designedto have rheological characteristics which permit it to be formulated onthe surface with reasonable convenience and to be pumped down the wellwithout excessive difficulty or pressure drop frictional losses.

The most commonly used fracturing fluids are water-based compositionscontaining a water soluble hydratable high molecular weight polymer,which increases the viscosity of the fluid by forming a gel when itdissolves in the fluid. Thickening the fluid reduces leakage of liquidsfrom the fracturing fluid into the formation during fracturing andincreases proppant suspension capability.

In some fracturing fluid formulations, chemical agents are added tocrosslink the polymer viscosifier molecules to further increase fluidviscosity. Cross-linking increases fluid viscosity by forminginterpolymer chemical bonds.

When the fracturing operation is complete, the pressure of thefracturing fluid in the formation is reduced. Fracturing fluid flowsback out of the formation into the well. Fracturing fluids are designedto flow quickly and completely out of the formation and back into thewell to allow production of hydrocarbons. Although hydratable polymersnaturally decompose over time, these natural degradation processes aregenerally too slow resulting in too great of a loss of production timeif producers were required to wait for natural degradation processes tobreak the fracturing fluid viscosity. To enhance back flow of fracturingfluid out of the formation and into the well, compounds are added to thefluid (initially or subsequent to fracturing) to reduce or “break” theviscosity of the fracturing fluid so that the fluid can flow more freelyand be removed from the formation into the well more quickly.

Fracturing fluid viscosity breaking also is utilized to minimize damageto the formation. As the fracturing operation proceeds, the thickeningagents in the fracturing fluid can form a thin film over the fractureface which is referred to as a “filter-cake.” Excessive filter cakes canimped the flow of production fluids from the formation into the well.

It has been reported in the literature that enzymes can be used todegrade drilling fluid residues. For example, Hanssen, et al., “NewEnzyme Process for Downhole Cleanup of Reservoir Drilling Filter cake”SPE 50709 (1999) disclosed experimental work towards the use of enzymesfor downhole cleanup of filter cakes produced by water-based drillingfluids.

U.S. Pat. No. 5,247,995 (incorporated herein by reference) disclosedmethod of degrading damaging material within a subterranean formation ofa well bore using an enzyme treatment. Filter cakes and very viscousfluids are such damaging materials. The enzyme treatment degradespolysaccharide-containing filter cakes and damaging fluids which reducestheir viscosity. The degraded filter cake and damaging fluid can then beremoved from the formation back to the well surface. The particularenzymes utilized are specific to a particular type of polysaccharide andare active at low to moderate temperatures. The enzymes attack onlyspecific linkages in filter cakes and damaging fluids and are active inthe pH range of about 2.0 to 10.0.

Simply adding the enzymes to the fluid may lead to premature breaking ofthe fluid. U.S. Pat. No. 5,437,331 disclosed a method of fracturing asubterranean formation in a well bore is shown in which a gellablefracturing fluid is first formed by blending together an aqueous fluid,a hydratable polymer, a suitable cross-linking agent for cross-linkingthe hydratable polymer to form a polymer gel and an encapsulated enzymebreaker. The cross-linked polymer gel is pumped into the well bore undersufficient pressure to fracture the surrounding formation. Theencapsulated enzyme breaker is allowed to degrade the cross-linkedpolymer with time to reduce the viscosity of the fluid so that the fluidcan be pumped from the formation back to the well surface. Theparticular enzyme breaker uses open cellular encapsulation to protectand delay the action of the enzyme.

Although enzyme type breakers have been used, there use has been limiteddo to release dynamics and duration of activity, there is still a needin the art for compositions and methods of breaking a fracturing fluidin a controlled manner over a controlled or designed period of time.

DEFINITIONS OF THE INVENTION

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “surfactant” refers to a soluble, or partially soluble compoundthat reduces the surface tension of liquids, or reduces inter-facialtension between two liquids, or a liquid and a solid by congregating andorienting itself at these interfaces.

The term “amphoteric” refers to surfactants that have both positive andnegative charges. The net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution.

The term “anionic” refers to those surfactants that possess a netnegative charge.

The term “cationic” refers to those surfactants that possess a netpositive charge.

The term “fracturing” refers to the process and methods of breaking downa geological formation, i.e. the rock formation around a well bore, bypumping fluid at very high pressures, in order to increase productionrates from a hydrocarbon reservoir. The fracturing methods of thisinvention use otherwise conventional techniques known in the art.

The term “proppant” refers to a granular substance suspended in thefracturing fluid during the fracturing operation, which serves to keepthe formation from closing back down upon itself once the pressure isreleased. Proppants envisioned by the present invention include, but arenot limited to, conventional proppants familiar to those skilled in theart such as sand, 20-40 mesh sand, resin-coated sand, sintered bauxite,glass beads, and similar materials.

SUMMARY OF THE INVENTION

The present invention provides apparatuses and methods for reducing aviscosity of a gelled fluid and degrading filter cake formed by thefluid. In one embodiment, a viscosity reducing microbe is disposed in acapsule and added to the gelled fluid. The gelled fluid may include athickening agent adapted to increase its viscosity. The capsulecontaining the microbe is designed to rupture releasing the microbe at adesignated time. Once released, the microbe and/or enzymes produced bythe microbe begin to digest or breakdown the thickening agent in thegelled fluid into low molecular weight materials. This breakdown breaksthe viscosity of the gelled fluid in a controlled manner.

The present invention also provides a method for reducing a viscosity ofa gelled fluid, where the method comprises forming a gelled fluid. Themethod also includes the step of adding an effective amount of aviscosity reducing microbe sufficient to reduce the viscosity of thegelled fluid to a desired lower viscosity in a controlled manner.

The present invention also provides a method for reducing a viscosity ofa gelled fluid, where the method comprises forming a gelled fluid. Themethod also includes the step of adding an effective amount of anencapsulated viscosity reducing microbe sufficient to reduce theviscosity of the gelled fluid. The method also includes the step ofreleasing the microbe in a controlled manner based on the breakdown ofthe encapsulating agent either due to a change in temperature, exposureto an aqueous fluid, a changed pH, a change in pressure, a change inshear, the addition of an additive designed to remove or destroy theencapsulating agent, or a combination of some or all of thesedeencapsulating condition. The method also includes the step of exposingthe viscosity reducing microbe to the gelled fluid as it is releasedfrom the encapsulating agent, where the released microbe and/or enzymesproduced by the microbe to reduce the viscosity of the gelled fluid in acontrolled manner.

The present invention also provides a method for reducing a viscosity ofa gelled fluid, where the method comprises forming a gelled fluid. Themethod also includes the step of adding an effective amount of a mixtureof a microbe and/or an encapsulated viscosity reducing microbesufficient to reduce the viscosity of the gelled fluid, where thenon-encapsulated microbe begins viscosity breakdown and encapsulatedmicrobe deencapsulates to change the viscosity breakdown dynamics. Bychanging the mixture of a microbe composition and an encapsulatedmicrobe composition, the viscosity of the mixture can be tailored toachieve a desired and controlled viscosity breakdown of a gelled fluid.In certain embodiments, the microbe compositions can be combined withtraditional breakers to further augment and control the viscositybreakdown dynamics.

The present invention also provides an apparatus for reducing viscosityof a gelled fluid includes a capsule and a viscosity reducing microbedisposed within the capsule, wherein the capsule is adapted to releasethe viscosity reducing microbe into a gelled fluid over time.

The present invention provides an apparatus for reducing viscosity of agelled fluid includes a capsule and a viscosity reducing microbedisposed within the capsule, wherein the capsule is adapted to delay arelease of the microbe to control the onset of the viscosity breakdown.

The present invention provides a fluid composition for wellboreoperations includes an aqueous fluid; a fluid thickener; and a capsulecontaining a viscosity reducing microbe, wherein the viscosity reducingmicrobe is adapted to degrade the fluid thickener upon contact therewithin a controlled manner.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the followingdetailed description together with the appended illustrative drawings inwhich like elements are numbered the same:

FIG. 1 shows the results of the viscosity reducing effects of anembodiment of a microbial composition, in an unencapsulated andencapsulated form at pH 7.

FIG. 2 shows the results of the viscosity reducing effects of theembodiment of a microbial composition, in an unencapsulated andencapsulated form at pH 10.

FIG. 3 shows the results of the viscosity reducing effects of anotherembodiment of a microbial composition, in an unencapsulated andencapsulated form at pH 7 and pH 10.

FIG. 4 shows the results of the viscosity reducing effects of anembodiment of a microbial composition, in an unencapsulated andencapsulated form at a pH between about 7.9 and 8.7 in tap water.

FIG. 5 shows the results of the viscosity reducing effects of anembodiment of a microbial composition, in an unencapsulated andencapsulated form at a pH between about 9.9 and 10.8 in tap water.

FIG. 6 shows the results of the viscosity reducing effects of anotherembodiment of a microbial composition, in an unencapsulated andencapsulated form at pH 7 and pH 10 in the presence of BIO-CLEAR® 200 (aregistered trademark of Clearwater International, LLC) available fromClearwater International, LLC of Houston, Tex.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have found apparatuses, compositions and methods can beimplemented to break a viscosity of a gelled fluid, especially, gelledfracturing fluids. The apparatuses, compositions and methods all involvethe use of a gelled fluid capable of being viscosity reduced due to theaction of a microbe and/or enzymes produces by the microbe, when themicrobial composition is brought in contact with a gelled fluid. Theinventors have found that the amount and form of the microbialcomposition can be tailored to achieve a given rate of viscositybreakdown and/or a given viscosity breakdown profile.

Embodiments of the present invention provide apparatus and methods ofreducing the viscosity of a gelled fluid. In one embodiment, a viscosityreducing microbe is disposed in a capsule and added to the gelled fluid.The gelled fluid may include a thickening agent adapted to increase itsviscosity. Upon release from the capsule, the microbe begins to digestthe thickening agent in the gelled fluid and/or releases enzymes thatthat breakdown the thickening agent.

In one embodiment, viscosity reducing microbes may include any bacteriaor fungus capable of digesting or degrading the thickening agent in thegelled fluid, thereby reducing the viscosity of the gelled fluid. Themicrobes may produce biochemicals such as enzymes to degrade thetargeted gelled fluid or filter cake. The microbe may live in the gelledfluid to continuously reduce the viscosity of the gelled fluid.Additionally, the microbe may imbed itself in the filter cake and digestor degrade the filter cake.

The present invention relates to a method for reducing viscosity of agelled fluid, comprising forming a gelled fluid; and adding an effectiveamount of a microbial composition to the fluid to reduce the viscosityof the gelled fluid, where the microbial composition includes aviscosity reducing microbe.

The present invention relates to a method for reducing viscosity of agelled fluid, comprising forming a gelled fluid. A first amount of afirst microbial composition is then added to the fluid, where the firstmicrobial composition comprises a viscosity reducing microbe. A secondamount of a second microbial composition is added to the fluid, wherethe second microbial composition comprises a viscosity reducing microbesurrounded by an encapsulating agent. The first and second amounts areadjusted to produce a desired viscosity reduction profile. The amountscan be added together or separately.

The present invention relates to a method for reducing viscosity of agelled fluid, comprising forming a gelled fluid and adding an effectiveamount of a releasable microbial composition comprising a viscosityreducing microbe. The releasable microbial composition is released inresponse to a change in a fluid property, where the release microbe orenzymes produced by the microbe reduce the viscosity to a desired valueor according to a controlled viscosity reduction profile. The fluidproperty can be temperature, pressure, pH, an additive, an activatingagent, or a mixture thereof.

The present invention relates to an apparatus for reducing viscosity ofa gelled fluid, comprising a capsule containing a viscosity reducingmicrobe disposed within the capsule, wherein the capsule is adapted torelease the viscosity reducing microbe into gelled fluid over time or inresponse to a change in a fluid property. Again, the fluid property canbe temperature, pressure, pH, an additive, an activating agent, or amixture thereof.

The present invention relates to an apparatus for reducing viscosity ofa gelled fluid, comprising an outer shell and an interior filled with aviscosity reducing microbe. The outer shell is adapted to rupture inresponse to a change in a fluid property and once ruptured to release aviscosity reducing microbe disposed within the capsule.

The present invention relates to a fluid composition for wellboreoperations, comprising an aqueous fluid, a fluid thickener; and acapsule containing a viscosity reducing microbe, where the viscosityreducing microbe, once released into the fluid, is adapted to degradethe fluid thickener upon contact therewith and where the capsule isdesigned to release the microbe in response to a change in a fluidproperty.

The present invention relates to a composition for fracturing asubterranean formation containing a gas and/or crude oil and penetratedby a wellbore, the composition comprising a fracturing fluid. Thefracturing fluid includes a gelled fluid and a microbial viscosityreducing composition, where the viscosity reducing microbe is adapted todegrade the fluid thickener upon contact therewith.

The present invention relates to a method for fracturing a formationcomprising pumping, into a producing formation at a pressure sufficientto fracture the formation and to enhance productivity, a fracturingfluid comprising a gelled fluid comprising a microbial digestiblethickening agent, where the gelled fluid raises the viscosity of fluidto enhance the formation for fracture in the formation, and a proppant,where the proppant props opened fracturing formed in the formation. Themethod also includes injecting a microbial composition comprising aviscosity reducing microbe in the fluid, where the composition reducesthe viscosity of the gelled fluid.

The present invention relates to a method for fracturing a formationincluding the step of pumping a fracturing fluid into a producingformation at a pressure sufficient to fracture the formation and toenhance productivity, where the fluid comprises a gelled fluidcomprising a microbial digestible thickening agent, where the gelledfluid raises the viscosity of fluid to enhance the formation forfracture in the formation. The method also includes the step of pumpingin a proppant fluid including a proppant, where the proppant propsopened fracturing formed in the formation. The method also includes thestep of injecting a microbial composition comprising a viscosityreducing microbe in the fluid, where the composition reduces theviscosity of the gelled fluid.

The present invention relates to a method for fracturing a formationincluding the step of pumping a fracturing fluid into a producingformation at a pressure sufficient to fracture the formation and toenhance productivity, where the fluid comprises a gelled fluidcomprising a microbial digestible thickening agent, where the gelledfluid raises the viscosity of fluid to enhance the formation forfracture in the formation. The method also includes the step pumping ina proppant fluid including a proppant, where the proppant props openedfracturing formed in the formation The method also includes the steppumping a delayed microbial composition comprising a viscosity reducingmicrobe in the fluid, where the composition is adapted to rupture inresponse to a change in a fluid property. The method also includes thestep changing a fluid property to release the microbe.

Suitable Reagents

Suitable viscosity reducing microbes include, without limitation, anybacteria or other microorganism capable of breaking down or digesting athickening agent used in a gelled fluid. Exemplary viscosity reducingmicrobes include bacteria from the Thermotogas species, which is a groupof hyperthermophilic bacteria, such as Thermotoga neapolitana andThermotoga maritime. Suitable bacteria also include those in the classBacillus, Citrobacter, and Enterococcus, such as Bacillus subtilis,Citrobacter freundii, and Enterococcus faecalies. Viscosity reducingmicrobes may also be a fungus such as Aspergillus niger. In oneembodiment, one or more types of microbes may be combined and used toreduce the viscosity of the fluid and degrade the filter cake. Exemplaryviscosity reducing bacteria are disclosed in U.S. Pat. No. 6,110,875,which is incorporate herein by reference. These microbes can be in theform of the microbes themselves or encapsulated in an encapsulatingagent.

In one embodiment, the microbe may be selected for its ability to digestor degrade a specific polymeric thickening agent. For example,Thermotoga neapolitana is known to produce hydrolases. Hydrolases are aclass of enzymes suitable for treating guar-containing filter cakes.These enzymes attack the mannosidic and galactomannosidic linkages inthe guar residue, breaking the molecules into monosaccharide anddisaccharide fragments. Under some conditions, these enzymes hydrolyzethe residue completely into monosaccharide fragments. The preferredenzymes for the guar-containing filter cake are galactomannan hydrolasescollectively called galactomannanase, and they specifically hydrolyzethe (1,6)-α-D-galactomannosidic and the (1,4)-β-D-mannosidic linkagesbetween the monosaccharide units in the guar-containing filter cake,respectively.

In addition to hydrolases, other suitable enzymes for reducing viscosityof gelled fluids include cellulase, hemicellulases, glucosidases,endoxylanase, exo-xylanase, endo-amylases, oxidase, and combinationsthereof. Other exemplary viscosity reducing enzymes are disclosed inU.S. Pat. Nos. 5,247,995 and 6,818,594, which are incorporated herein byreference.

Suitable downhole environments for the microbes include a temperaturerange between about 50° F. and about 250° F. In certain embodiments, thetemperature range is between about 80° F. and about 195° F. The pHshould be in range between about 2 pH to about 11 pH. In certainembodiments, the pH ranges between about 4 pH and about 9 pH. Inaddition, metabolic activity of the microbes may be controlled byadjusting the downhole conditions. For example, metabolic activity ofthe microbe may be enhanced by increasing the temperature to the upperrange.

The viscosity reducing microbe may be encapsulated to allow a delayedreleased composition. In one embodiment, the microbe may be physicallysequestered within a polymeric capsule impermeable to the microbe. Themicrobe may be contained in liquid when added to the capsule. Forexample, the microbe may be trapped in a functional polymer matrix thatis pH sensitive, with the microbe being released by adjusting the pH ofthe surrounding fluid. For example, if the encapsulating matrix isdestroyed at high pH, then after injection or during injection of theencapsulated composition, the pH can be raised resulting in microberelease. Another example is to precipitate the microbe and trap themicrobe within a semi-permeable nylon shell, where the shell is thendisrupted by raising the pH of the surrounding fluid to a high pH.

Suitable encapsulating agents include, without limitation, anyencapsulating agent that is adapted to encapsulate microbes and arecapable of being released by a change in temperature, exposure of anaqueous solution in the presence or absence of an encapsulateddegradation agent, a change in pH, a change in pressure, a change inshear, or a combination of any of these conditions.

In other embodiments, the microbe is encapsulated by an acid- oralkaline-responsive material that is caused to release the microbe inresponse to an appropriate pH change in the capsule surroundings.Various materials and techniques for encapsulating compounds and enzymesunder conditions compatible with maintaining the activity of enzymes aredisclosed in one or more of the following U.S. Pat. Nos. 4,202,795,5,837,290; 5,805,264; 5,310,721; 4,978,481; 4,968,532; 4,619,764;4,003,846; 5,094,785 or in PCT publication WO 97/24178. The disclosuresof these patents are incorporated herein by reference. Additionalguidance for encapsulating compounds and enzymes under acceptableconditions is provided in one or more of the following U.S. Pat. Nos.5,492,646; 5,460,817; 5,194,263; 5,035,900; 5,324,445; 5,972,363;5,972,387; 5,968,794; 5,965,121; 5,962,015; 5,955,503; 5,932,385;5,916,790; 5,914,182; 5,908,623; and 5,895,757. The disclosures of thesepatents are incorporated herein by reference.

In another embodiment, the encapsulation method involves introducing themicrobe into hollow or porous, crushable and fragile beads. The beadsare then added to the gelled fluid and introduce into the subterraneanformation under pressure. When the fracturing fluid passes or leaks offinto the formation, or the fluid is removed by back flowing, theresulting fractures in the subterranean formation close and crush thebeads. The crushing of the beads then releases the viscosity-reducingmicrobes into the fluid. An example of this process is disclosed in U.S.Pat. No. 4,506,734, which is incorporated herein by reference.

The viscosity reducing microbes may be used to break the viscosity ofgelled fluids formed by adding thickening agents such as hydratingpolymers and viscoelastic surfactants. In one embodiment, an aqueousfracturing fluid is first prepared by blending a hydratable polymer intoan aqueous fluid. The aqueous fluid could be, for example, water, brine,aqueous based foams or water-alcohol mixtures. Any suitable mixingapparatus may be used for this procedure. In the case of batch mixing,the hydratable polymer and the aqueous fluid are blended for a period oftime sufficient to form a hydrated solution.

A wide variety of hydratable water soluble polymers are used infracturing fluid formulations including polysaccharides,polyacrylamides, and polyacrylamide copolymers. Suitable polysaccharidesinclude galactomannan gum and cellulose derivatives. Preferredpolysaccharides include guar gum, locust bean gum, carboxymethylguar,hydroxyethylguar, hydroxypropylguar, carboxymethylhydroxypropylguar,carboxymethylhydroxyethylguar, hydroxymethyl cellulose,carboxymethylhydroxyethyl cellulose, and hydroxyethyl cellulose.

The hydratable polymer useful in the present invention can be any of thehydratable polysaccharides having galactose or mannose monosaccharidecomponents and are familiar to those in the well service industry. Thesepolysaccharides are capable of gelling in the presence of a crosslinkingagent to form a gelled based fluid. For instance, suitable hydratablepolysaccharides are the galactomannan gums, guars and derivatized guars.Specific examples are guar gum and guar gum derivatives. Suitablegelling agents are guar gum, hydroxypropyl guar and carboxymethylhydroxypropyl guar. In certain embodiment, the hydratable polymers forthe present invention are guar gum and carboxymethyl hydroxypropyl guarand hydroxypropyl guar. Other exemplary fracturing fluid formulationsare disclosed in U.S. Pat. Nos. 5,201,370 and 6,138,760, which areincorporated herein by reference.

The hydratable polymer is added to the aqueous fluid in concentrationsranging from about 0.12% to 0.96% by weight of the aqueous fluid. Incertain embodiments, the range for the present invention is about 0.3%to about 0.48% by weight.

In addition to the hydratable polymer, the fracturing fluids of theinvention include a crosslinking agent. The crosslinking agent can beany of the conventionally used crosslinking agents which are known tothose skilled in the art. For instance, in recent years, gellation ofthe hydratable polymer has been achieved by crosslinking these polymerswith metal ions including aluminum, antimony, zirconium and titaniumcontaining compounds including the so-called organotitinates. See, forinstance, U.S. Pat. No. 4,514,309. Recent research indicates that guargels, which are crosslinked by the additions of borate ion donatingmaterials, clean up faster and yield higher sand pack permeability thanguar gels crosslinked with other crosslinking agents. As a result, theborate crosslinking agents are preferred. Common crosslinking agentsinclude polyvalent ions in their high valance state such as Al(III),Ti(IV), Zr(IV) in the form of salts of organic acids.

In the case of the borate crosslinkers, the crosslinking agent is anymaterial which supplies borate ions in solution. Thus the crosslinkingagent can be any convenient source of borate ions, for instance thealkali metal and the alkaline earth metal borates and boric acid. Apreferred crosslinking additive is sodium borate decahydrate. Thiscrosslinking additive is preferably present in the range from about0.024% to in excess of 0.18% by weight of the aqueous fluid. Preferably,the concentration of crosslinking agent is in the range from about0.024% to about 0.09% by weight of the aqueous fluid.

Propping agents are typically added to the base fluid prior to theaddition of the crosslinking agent. Propping agents include, forinstance, quartz sand grains, glass and ceramic beads, walnut shellfragments, aluminum pellets, nylon pellets, and the like. The proppingagents are normally used in concentrations between about 1 to 18 poundsper gallon of fracturing fluid composition, but higher or lowerconcentrations can be used as required. The base fluid can also containother conventional additives common to the well service industry such assurfactants, and the like.

In a typical fracturing operation, the fracturing fluid is pumped at arate sufficient to initiate and propagate a fracture in the formationand to place propping agents into the fracture. A typical fracturingtreatment would be conducted by hydrating a 0.24% to 0.72%(weight/volume [w/v]) galactomannan based polymer, such as guar, in a 2%(w/v) KCl solution. In addition to the encapsulated viscosity reducingmicrobes, the fracturing fluid may include additives such as thecrosslinking agent, proppant, and other additives.

Fracturing Fluids

Generally, a hydraulic fracturing treatment involves pumping aproppant-free viscous fluid, or pad, usually water with some fluidadditives to generate high viscosity, into a well faster than the fluidcan escape into the formation so that the pressure rises and the rockbreaks, creating artificial fracture and/or enlarging existing fracture.After fracturing the formation, a propping agent, generally a solidmaterial such as sand is added to the fluid to form a slurry that ispumped into the newly formed fractures in the formation to prevent themfrom closing when the pumping pressure is released. The proppanttransport ability of a base fluid depends on the type of viscosifyingadditives added to the water base.

Water-base fracturing fluids with water-soluble polymers added to make aviscosified solution are widely used in the art of fracturing. Since thelate 1950s, more than half of the fracturing treatments are conductedwith fluids comprising guar gums, high-molecular weight polysaccharidescomposed of mannose and galactose sugars, or guar derivatives such ashydropropyl guar (HPG), carboxymethyl guar (CMG).carboxymethylhydropropyl guar (CMHPG). Crosslinking agents based onboron, titanium, zirconium or aluminum complexes are typically used toincrease the effective molecular weight of the polymer and make thembetter suited for use in high-temperature wells.

To a lesser extent, cellulose derivatives such as hydroxyethylcellulose(HEC) or hydroxypropylcellulose (HPC) andcarboxymethylhydroxyethylcellulose (CMHEC) are also used, with orwithout crosslinkers. Xanthan and scleroglucan, two biopolymers, havebeen shown to have excellent proppant-suspension ability even thoughthey are more expensive than guar derivatives and therefore used lessfrequently. Polyacrylamide and polyacrylate polymers and copolymers areused typically for high-temperature applications or friction reducers atlow concentrations for all temperatures ranges.

Polymer-free, water-base fracturing fluids can be obtained usingviscoelastic surfactants. These fluids are normally prepared by mixingin appropriate amounts of suitable surfactants such as anionic,cationic, nonionic and zwitterionic surfactants. The viscosity ofviscoelastic surfactant fluids is attributed to the three dimensionalstructure formed by the components in the fluids. When the concentrationof surfactants in a viscoelastic fluid significantly exceeds a criticalconcentration, and in most cases in the presence of an electrolyte,surfactant molecules aggregate into species such as micelles, which caninteract to form a network exhibiting viscous and elastic behavior.

The proppant type can be sand, intermediate strength ceramic proppants(available from Carbo Ceramics, Norton Proppants, etc.), sinteredbauxites and other materials known to the industry. Any of these basepropping agents can further be coated with a resin (available fromSantrol, a Division of Fairmount Industries, Borden Chemical, etc.) topotentially improve the clustering ability of the proppant. In addition,the proppant can be coated with resin or a proppant flowback controlagent such as fibers for instance can be simultaneously pumped. Byselecting proppants having a contrast in one of such properties such asdensity, size and concentrations, different settling rates will beachieved.

“Waterfrac treatments employ the use of low cost, low viscosity fluidsin order to stimulate very low permeability reservoirs. The results havebeen reported to be successful (measured productivity and economics) andrely on the mechanisms of asperity creation (rock spalling), sheardisplacement of rock and localized high concentration of proppant tocreate adequate conductivity. It is the last of the three mechanismsthat is mostly responsible for the conductivity obtained in “waterfrac”treatments. The mechanism can be described as analogous to a wedgesplitting wood.

An aqueous fracturing fluid may be prepared by blending a hydratablepolymer with an aqueous base fluid. The base aqueous fluid can be, forexample, water or brine. Any suitable mixing apparatus may be used forthis procedure. In the case of batch mixing, the hydratable polymer andaqueous fluid are blended for a period of time which is sufficient toform a hydrated sol.

Hydraulic fracturing techniques are widely employed to enhance oil andgas production from subterranean formations. During hydraulicfracturing, fluid is injected into a well bore under high pressure. Oncethe natural reservoir pressures are exceeded, the fracturing fluidinitiates a fracture in the formation which generally continues to growduring pumping. As the fracture widens to a suitable width during thecourse of the treatment, a propping agent is then also added to thefluid. The treatment design generally requires the fluid to reach amaximum viscosity as it enters the fracture which affects the fracturelength and width. The viscosity of most fracturing fluids is generatedfrom water-soluble polysaccharides, such as galactomannans or cellulosederivatives. Employing crosslinking agents, such as borate, titanate, orzirconium ions, can further increase the viscosity. The gelled fluid maybe accompanied by a propping agent (i.e., proppant) which results inplacement of the proppant within the fracture thus produced. Theproppant remains in the produced fracture to prevent the completeclosure of the fracture and to form a conductive channel extending fromthe well bore into the formation being treated once the fracturing fluidis recovered.

In order for the treatment to be successful, it is preferred that thefluid viscosity eventually diminish to levels approaching that of waterafter the proppant is placed. This allows a portion of the treatingfluid to be recovered without producing excessive amounts of proppantafter the well is opened and returned to production. The recovery of thefracturing fluid is accomplished by reducing the viscosity of the fluidto a lower value such that it flows naturally from the formation underthe influence of formation fluids. This viscosity reduction orconversion is referred to as “breaking” and can be accomplished byincorporating chemical agents, referred to as “breakers,” into theinitial gel.

Certain gels of fracturing fluids, such as those based upon guarpolymers, undergo a natural break without the intervention of a breakingagent. However, the breaking time for such gelled fluids generally isexcessive and impractical, being somewhere in the range from greaterthan 24 hours to in excess of weeks, months, or years depending onreservoir conditions. Accordingly, to decrease the break time of gelsused in fracturing, chemical agents are usually incorporated into thegel and become a part of the gel itself. Typically, these agents areeither oxidants or enzymes which operate to degrade the polymeric gelstructure. Most degradation or “breaking” is caused by oxidizing agents,such as persulfate salts (used either as is or encapsulated), chromoussalts, organic peroxides or alkaline earth or zinc peroxide salts, or byenzymes.

In addition to the importance of providing a breaking mechanism for thegelled fluid to facilitate recovery of the fluid and to resumeproduction, the timing of the break is also of great importance. Gelswhich break prematurely can cause suspended proppant material to settleout of the gel before being introduced a sufficient distance into theproduced fracture. Premature breaking can also lead to a prematurereduction in the fluid viscosity, resulting in a less than desirablefracture width in the formation causing excessive injection pressuresand premature termination of the treatment.

On the other hand, gelled fluids which break too slowly can cause slowrecovery of the fracturing fluid from the produced fracture withattendant delay in resuming the production of formation fluids andseverely impair anticipated hydrocarbon production. Additional problemsmay occur, such as the tendency of proppant to become dislodged from thefracture, resulting in at least partial closing and decreased efficiencyof the fracturing operation. Preferably, the fracturing gel should beginto break when the pumping operations are concluded. For practicalpurposes, the gel preferably should be completely broken within about 24hours after completion of the fracturing treatment. Gels useful in thisregard include those disclosed in U.S. Pat. Nos. 3,960,736; 5,224,546;6,756,345; and 6,793,018, incorporated herein by reference.

Suitable solvents fore use in this invention include, withoutlimitation, water. The solvent may be an aqueous potassium chloridesolution.

Suitable inorganic breaking agent include, without limitation, ametal-based oxidizing agent, such as an alkaline earth metal or atransition metal; magnesium peroxide, calcium peroxide, or zincperoxide.

Suitable ester compound include, without limitation, an ester of apolycarboxylic acid, e.g., an ester of oxalate, citrate, or ethylenediamine tetraacetate. Ester compound having hydroxyl groups can also beacetylated, e.g., acetylated citric acid to form acetyl triethylcitrate.

Suitable hydratable polymers that may be used in embodiments of theinvention include any of the hydratable polysaccharides which arecapable of forming a gel in the presence of a crosslinking agent. Forinstance, suitable hydratable polysaccharides include, but are notlimited to, galactomannan gums, glucomannan gums, guars, derived guars,and cellulose derivatives. Specific examples are guar gum, guar gumderivatives, locust bean gum, Karaya gum, carboxymethyl cellulose,carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.Presently preferred gelling agents include, but are not limited to, guargums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitablehydratable polymers may also include synthetic polymers, such aspolyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propanesulfonic acid, and various other synthetic polymers and copolymers.Other suitable polymers are known to those skilled in the art.

The hydratable polymer may be present in the fluid in concentrationsranging from about 0.10% to about 5.0% by weight of the aqueous fluid.In certain embodiment, a range for the hydratable polymer is about 0.20%to about 0.80% by weight.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. For example, the gellation of a hydratablepolymer can be achieved by crosslinking the polymer with metal ionsincluding boron, zirconium, and titanium containing compounds, ormixtures thereof. One class of suitable crosslinking agents isorganotitanates. Another class of suitable crosslinking agents isborates as described, for example, in U.S. Pat. No. 4,514,309. Theselection of an appropriate crosslinking agent depends upon the type oftreatment to be performed and the hydratable polymer to be used. Theamount of the crosslinking agent used also depends upon the wellconditions and the type of treatment to be effected, but is generally inthe range of from about 10 ppm to about 1000 ppm of metal ion of thecrosslinking agent in the hydratable polymer fluid. In someapplications, the aqueous polymer solution is crosslinked immediatelyupon addition of the crosslinking agent to form a highly viscous gel. Inother applications, the reaction of the crosslinking agent can beretarded so that viscous gel formation does not occur until the desiredtime.

The organotitanate constituent can be TYZOR® titanium chelate estersfrom E.I du Pont de Nemours & Company. The organotitanate constituentcan be a mixture of a first organotitanate compound having a lactatebase and a second organotitanate compound having triethanolamine base.

The boron constituent can be selected from the group consisting of boricacid, sodium tetraborate, and mixtures thereof. These are described inU.S. Pat. No. 4,514,309.), borate based ores such as ulexite andcolemanite, Ti(IV) acetylacetonate, Ti(IV) triethanolamine, Zr lactate,Zr triethanolamine, Zr lactate-triethanolamine, or Zrlactate-triethanolamine-triisopropanolamine. In some embodiments, thewell treatment fluid composition may further comprise a proppant.

“Premature breaking” as used herein refers to a phenomenon in which agel viscosity becomes diminished to an undesirable extent before all ofthe fluid is introduced into the formation to be fractured. Thus, to besatisfactory, the gel viscosity should preferably remain in the rangefrom about 50% to about 75% of the initial viscosity of the gel for atleast two hours of exposure to the expected operating temperature.Preferably the fluid should have a viscosity in excess of 100 centipoise(cP) at 100 sec⁻¹ while injection into the reservoir as measured on aFann 50 C viscometer in the laboratory.

“Complete breaking” as used herein refers to a phenomenon in which theviscosity of a gel is reduced to such a level that the gel can beflushed from the formation by the flowing formation fluids or that itcan be recovered by a swabbing operation. In laboratory settings, acompletely broken, non-crosslinked gel is one whose viscosity is about10 cP or less as measured on a Model 35 Fann viscometer having a R1B1rotor and bob assembly rotating at 300 rpm.

The pH of an aqueous fluid which contains a hydratable polymer can beadjusted if necessary to render the fluid compatible with a crosslinkingagent. Preferably, a pH adjusting material is added to the aqueous fluidafter the addition of the polymer to the aqueous fluid. Typicalmaterials for adjusting the pH are commonly used acids, acid buffers,and mixtures of acids and bases. For example, sodium bicarbonate,potassium carbonate, sodium hydroxide, potassium hydroxide, and sodiumcarbonate are typical pH adjusting agents. Acceptable pH values for thefluid may range from neutral to basic, i.e., from about 5 to about 14.Preferably, the pH is kept neutral or basic, i.e., from about 7 to about14, more preferably between about 8 to about 12.

The term “breaking agent” or “breaker” refers to any chemical that iscapable of reducing the viscosity of a gelled fluid. As described above,after a fracturing fluid is formed and pumped into a subterraneanformation, it is generally desirable to convert the highly viscous gelto a lower viscosity fluid. This allows the fluid to be easily andeffectively removed from the formation and to allow desired material,such as oil or gas, to flow into the well bore. This reduction inviscosity of the treating fluid is commonly referred to as “breaking”.Consequently, the chemicals used to break the viscosity of the fluid isreferred to as a breaking agent or a breaker.

There are various methods available for breaking a fracturing fluid or atreating fluid. Typically, fluids break after the passage of time and/orprolonged exposure to high temperatures. However, it is desirable to beable to predict and control the breaking within relatively narrowlimits. Mild oxidizing agents are useful as breakers when a fluid isused in a relatively high temperature formation, although formationtemperatures of 300° F. (149° C.) or higher will generally break thefluid relatively quickly without the aid of an oxidizing agent.

Examples of inorganic breaking agents for use in this invention include,but are not limited to, persulfates, percarbonates, perborates,peroxides, perphosphates, permanganates, etc. Specific examples ofinorganic breaking agents include, but are not limited to, alkalineearth metal persulfates, alkaline earth metal percarbonates, alkalineearth metal perborates, alkaline earth metal peroxides, alkaline earthmetal perphosphates, zinc salts of peroxide, perphosphate, perborate,and percarbonate, and so on. Additional suitable breaking agents aredisclosed in U.S. Pat. Nos. 5,877,127; 5,649,596; 5,669,447; 5,624,886;5,106,518; 6,162,766; and 5,807,812. In some embodiments, an inorganicbreaking agent is selected from alkaline earth metal or transitionmetal-based oxidizing agents, such as magnesium peroxides, zincperoxides, and calcium peroxides.

In addition, enzymatic breakers may also be used in place of or inaddition to a non-enzymatic breaker. Examples of suitable enzymaticbreakers such as guar specific enzymes, alpha and beta amylases,amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, andhemi-cellulase are disclosed in U.S. Pat. Nos. 5,806,597 and 5,067,566.

A breaking agent or breaker may be used “as is” or be encapsulated andactivated by a variety of mechanisms including crushing by formationclosure or dissolution by formation fluids. Such techniques aredisclosed, for example, in U.S. Pat. Nos. 4,506,734; 4,741,401;5,110,486; and 3,163,219.

Generally, the temperature and the pH of a fracturing fluid affects therate of hydrolysis of an ester. For downhole operations, the bottom holestatic temperature (“BHST”) cannot be easily controlled or changed. ThepH of a fracturing fluid usually is adjusted to a level to assure properfluid performance during the fracturing treatment. Therefore, the rateof hydrolysis of an ester could not be easily changed by altering BHSTor the pH of a fracturing fluid. However, the rate of hydrolysis may becontrolled by the amount of an ester used in a fracturing fluid. Forhigher temperature applications, the hydrolysis of an ester may beretarded or delayed by dissolving the ester in a hydrocarbon solvent.Moreover, the delay time may be adjusted by selecting esters thatprovide more or less water solubility. For example, for low temperatureapplications, polycarboxylic esters made from low molecular weightalcohols, such as methanol or ethanol, are recommended. The applicationtemperature range for these esters could range from about 120° F. toabout 250° F. (about 49° C. to about 121° C.). On the other hand, forhigher temperature applications or longer injection times, esters madefrom higher molecular weight alcohols should preferably be used. Thehigher molecular weight alcohols include, but are not limited to, C₃-C₆alcohols, e.g., n-propanol, hexanol, and cyclohexanol.

Propping agents or proppants are typically added to the fracturing fluidprior to the addition of a crosslinking agent. However, proppants may beintroduced in any manner which achieves the desired result. Any proppantmay be used in embodiments of the invention. Examples of suitableproppants include, but are not limited to, quartz sand grains, glass andceramic beads, walnut shell fragments, aluminum pellets, nylon pellets,and the like. Proppants are typically used in concentrations betweenabout 1 to 8 lbs. per gallon of a fracturing fluid, although higher orlower concentrations may also be used as desired. The fracturing fluidmay also contain other additives, such as surfactants, corrosioninhibitors, mutual solvents, stabilizers, paraffin inhibitors, tracersto monitor fluid flow back, and so on.

The well treatment fluid composition in accordance with embodiments ofthe invention has many useful applications. For example, it may be usedin hydraulic fracturing, gravel packing operations, water blocking,temporary plugs for purposes of wellbore isolation and/or fluid losscontrol, and other well completion operations. One application of thefluid composition is to use it as a fracturing fluid. Accordingly,embodiments of the invention also provide a method of treating asubterranean formation. The method includes formulating a fracturingfluid comprising an aqueous fluid, a hydratable polymer, a crosslinkingagent, an inorganic breaking agent, and an ester compound; and injectingthe fracturing fluid into a bore hole to contact at least a part of theformation by the fracturing fluid under a sufficient pressure tofracture the formation. Initially, the viscosity of the fracturing fluidshould be maintained above at least 200 cP at 40 sec⁻¹ during injectionand, afterwards, should be reduced to less than 200 cP at 40 sec⁻¹.After the viscosity of the fracturing fluid is lowered to an acceptablelevel, at least a portion of the fracturing fluid is removed from theformation. During the fracturing process, a proppant can be injectedinto the formation simultaneously with the fracturing fluid. Preferably,the fracturing fluid has a pH around or above about 7, more preferablyin the range of about 8 to about 12.

It should be understood that the above-described method is only one wayto carry out embodiments of the invention. The following U.S. patentsdisclose various techniques for conducting hydraulic fracturing whichmay be employed in embodiments of the invention with or withoutmodifications: U.S. Pat. Nos. 6,169,058; 6,135,205; 6,123,394;6,016,871; 5,755,286; 5,722,490; 5,711,396; 5,551,516; 5,497,831;5,488,083; 5,482,116; 5,472,049; 5,411,091; 5,402,846; 5,392,195;5,363,919; 5,228,510; 5,074,359; 5,024,276; 5,005,645; 4,938,286;4,926,940; 4,892,147; 4,869,322; 4,852,650; 4,848,468; 4,846,277;4,830,106; 4,817,717; 4,779,680; 4,479,041; 4,739,834; 4,724,905;4,718,490; 4,714,115; 4,705,113; 4,660,643; 4,657,081; 4,623,021;4,549,608; 4,541,935; 4,378,845; 4,067,389; 4,007,792; 3,965,982; and3,933,205.

The liquid carrier can generally be any liquid carrier suitable for usein oil and gas producing wells. A presently preferred liquid carrier iswater. The liquid carrier can comprise water, can consist essentially ofwater, or can consist of water. Water will typically be a majorcomponent by weight of the fluid. The water can be potable ornon-potable water. The water can be brackish or contain other materialstypical of sources of water found in or near oil fields. For example, itis possible to use fresh water, brine, or even water to which any salt,such as an alkali metal or alkali earth metal salt (NaCO.sub.3, NaCl,KCl, etc.) has been added. The liquid carrier is preferably present inan amount of at least about 80% by weight. Specific examples of theamount of liquid carrier include 80%, 85%, 90%, and 95% by weight.

All the fracturing fluids described above are described herein inrelationship to the sole use or combined use of a microbial basedviscosity breaking composition, apparatus or method of this invention.Of course, the microbial based viscosity breaking composition, apparatusor method of this invention can be used in conjunction or combinationsof other gelling and breaking compositions to achieve a desiredfracturing and breaking profile (viscosity versus time profile).

EXPERIMENTS OF THE INVENTION Example 1

This example illustrates the breaking characteristics of an embodimentof a microbial composition designated GUM-BAC™ available from Micro-BacInternational, Inc. of Round Rock, Tex. compared to controls at pH 7over a 17 day period of time. The microbial composition is eitherunencapsulated or encapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)of a 2% KCl aqueous solution prepared using Sparklet bottled waterpurchased in San Antonio, Tex. The viscosity testing was carried out ata temperature of 150° F. and at a pH between 7.2 and 7.4. The sample 1,designated Blank, was the gelled fluid itself, without additives, andserved as a reference or control. The sample 2, designated Blank+0.05gpt Biocide, was prepared as above with the addition of 0.05 gpt of abiocide. The sample 3, designated Blank+5 gpt GUM-BAC™, was prepared asabove with the addition of 5 gpt of the microbial composition GUM-BAC™.The sample 4, designated Blank+5 ppt encapsulated GUM-BAC™, was preparedas above with the addition of 5 ppt an encapsulated composition ofGUM-BAC™. The results of the viscosity testing is tabulated in Table 1and shown graphically in FIG. 1.

TABLE 1 Viscosity Reduction Results of a GUM-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) in a Guar Gelled Fluid @ 150° F. and@ pH 7.2 to 7.4 Sample 2 Sample 3 Sample 4 Control + Control + Control +Time of Sample 1 0.05 gpt 5 gpt 5 ppt Evaluation Control BiocideGUM-BAC ™ GUM-BAC ™^(†) 2 hours 66.8 60.2 34.7 62.4 1 Day 26.6 26.5 7.625.3 2 Days 23.2 23.3 5.8 20.8 3 Days 19.7 22.3 5.8 18.2 7 Days 15.716.0 7.1 8.9 8 Days 13.0 14.4 4.6 8.6 11 Days 13.2 11.4 2.6 7.3 14 Days12.6 9.2 3.2 4.7 17 Days 12.7 8.04 — 6.0 ^(†)encapsulated

It can be seen from the data in Table 1 and in the plot of FIG. 1 thatafter two hours, the viscosity of the gelled fluid for Sample 3 haddecreased more than the other 3 samples. In fact, the viscosity profilefor Sample 3, indicates that the un-encapsulated microbial compositionwas a faster acting, higher breaking activity, composition than theencapsulated microbial composition. This result is likely due to thefact that the microbe in the unencapsulated compositions was effectivein reducing fluid viscosity immediately upon introduction and did nothave to wait for release from the encapsulating agent. The data alsoindicates that breaking onset and viscosity reduction can be controlledusing a microbial composition with or without encapsulation.

Example 2

This example illustrates the breaking characteristics of anotherembodiment of a microbial composition designated GUM-BAC™ available fromMicro-Bac International, Inc. of Round Rock, Tex. compared to controlsat pH 10 over a 17 day period of time. The microbial composition iseither unencapsulated or encapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)of a 2% KCl aqueous solution prepared using Sparklet bottled waterpurchased in San Antonio, Tex. The viscosity testing was carried out ata temperature of 150° F. and at a pH between 10.2 and 10.4. The sample1, designated Blank, was the gelled fluid itself, without additives, andserved as a reference or control. The sample 2, designated Blank+0.05gpt Biocide, was prepared as above with the addition of 0.05 gpt of abiocide. The sample 3, designated Blank+5 gpt GUM-BAC™, was prepared asabove with the addition of 5 gpt of the microbial composition GUM-BAC™.The sample 4, designated Blank+5 ppt encapsulated GUM-BAC™, was preparedas above with the addition of 5 ppt an encapsulated composition ofGUM-BAC™. The results of the viscosity testing is tabulated in Table 2and shown graphically in FIG. 2.

TABLE 2 Viscosity Reduction Results of a GUM-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) in a Guar Gelled Fluid @ 150° F. and@ pH 10.2 to 10.4 Sample 2 Sample 3 Sample 4 Control + Control +Control + Time of Sample 1 0.05 gpt 5 gpt 5 ppt Evaluation ControlBiocide GUM-BAC ™ GUM-BAC ™^(†) 2 hours 62.5 44.2 61.3 61.7 1 Day 14.410.6 15.6 14.8 2 Days 11.0 9.1 13.9 12.7 3 Days 11.2 8.6 12.2 11.3 7Days 10.6 9.2 11.2 8.9 8 Days 11.6 9.0 10.6 10.7 11 Days 10.2 8.2 9.89.5 14 Days 10.4 7.6 9.2 9.4 17 Days 9.7 7.6 8.0 9.5 ^(†)encapsulated

It can be seen from the data in Table 2 and in the plot of FIG. 2 thatat pH 10, the microbial compositions showed little improvement over thecontrol. Thus, the microbial compositions show some pH sensitivityevidencing higher activity as lower pH.

Example 3

This example illustrates the breaking characteristics of anotherembodiment of a microbial composition designated XG-BAC™ also availablefrom Micro-Bac International, Inc. of Round Rock, Tex. compared tocontrols at pH 7 and pH 10. The microbial composition is unencapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)in a 2% KCl aqueous solution prepared using Sparklet bottled waterpurchased in San Antonio, Tex. The viscosity testing was carried out ata temperature of 150° F. and at a pH of 7.19 and 10.43. The sample 1,designated Blank @ pH7.19, was the gelled fluid itself at pH 7.19,without additives, and served as a pH 7.19 reference or control. Thesample 2 designated Blank+5 gpt XG-BAC™, was prepared as above with theaddition of 5 gpt of XG-BAC™ also at pH 7.19. The sample 3, designatedBlank @ pH 10.43, was the gelled fluid itself at pH 10.43, withoutadditives, and served as a pH 10.43 reference or control. The sample 4,designated Blank+5 gpt XG-BAC™, was prepared as above with the additionof 5 gpt of XG-BAC™ at pH 10.43. The results of the viscosity testing istabulated in Table 3 and shown graphically in FIG. 3.

TABLE 3 Viscosity Reduction Results of a XG-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) in a Guar Gelled Fluid @ 150° F. and@ pH 7.19 and 10.43 Sample 2 Sample 4 Control + Control + Sample 1 5 gptSample 3 5 ppt Time of Control XG-BAC ™ Control XG-BAC ™^(†) Evaluation@ pH 7.19 @ pH 7.19 @ pH 10.43 @ pH 10.43 0 hours 60.2 59.9 58.2 58.7 1Day 31.7 27.8 12.6 12.1 2 Days 25.4 21.4 11.3 15.4 3 Days 12.6 12.1 10.110.3 7 Days 14.5 11.4 11.4 12.5 11 Days 12.7 8.8 10.9 10.3 15 Days 12.44.92 10.6 9.5 ^(†)encapsulated

It can be seen from the data in Table 3 and in the plot of FIG. 3 thatthe microbial compositions showed enhanced viscosity reduction activityat pH 7.19 than at pH 10.42. The data also showed again indicates thatthe un-encapsulated microbial composition was a faster acting, higherbreaking activity, composition than the encapsulated microbialcomposition. This result is likely due to the fact that the microbe inthe unencapsulated compositions was effective in reducing fluidviscosity immediately upon introduction and did not have to wait forrelease from the encapsulating agent. The data also indicates thatbreaking onset and viscosity reduction can be controlled using amicrobial composition with or without encapsulation.

Example 4

This example illustrates the breaking characteristics of anotherembodiment of a microbial composition designated GUM-BAC™ available fromMicro-Bac International, Inc. of Round Rock, Tex. compared to controlsat a pH between 7.9 and 8.7 over an 11 day period of time. The microbialcomposition is either unencapsulated or encapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)of a 2% KCl aqueous solution prepared using San Antonio tap water. Theviscosity testing was carried out at a temperature of 150° F. and at apH between 10.2 and 10.4. The sample 1, designated Blank, was the gelledfluid itself, without additives, and served as a reference or control.The sample 2, designated Blank+0.05 gpt Biocide, was prepared as abovewith the addition of 0.05 gpt of a biocide. The sample 3, designatedBlank+5 gpt GUM-BAC™, was prepared as above with the addition of 5 gptof the microbial composition GUM-BAC™. The sample 4, designated Blank+5ppt encapsulated GUM-BAC™, was prepared as above with the addition of 5ppt an encapsulated composition of GUM-BAC™. The results of theviscosity testing is tabulated in Table 4 and shown graphically in FIG.4.

TABLE 4 Viscosity Reduction Results of a GUM-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) in a Tap Water Based, Gua GelledFluid @ 150° F. Sample 2 Sample 3 Sample 4 Control + Control + Control +Time of Sample 1 0.05 gpt 5 gpt 5 ppt Evaluation Control BiocideGUM-BAC ™ GUM-BAC ™^(†) 0 hours 47.0 48.0 47.0 48.0 2 Days 38.9 41.030.9 36.2 4 Days 34.6 34.4 25.0 29.3 8 Days 27.6 27.2 21.1 17.0 11 Days20.1 21.9 16.6 14.8 ^(†)encapsulated

It can be seen from the data in Table 4 and in the plot of FIG. 4 thatmicrobial compositions are effective viscosity reducing agents. Again,the unencapsulated microbial composition was faster acting than theencapsulated microbial composition. In this study, the encapsulatedcompositions also showed good viscosity reduction and by Day 8, theencapsulated Sample 4 now showed greater viscosity reduction compared tothe unencapsulated Sample 3. The change between Day 4 and Day 8 ofSample 4 may be attributed to the release of a substantial amount of theactive material. Further, the additional viscosity reduction of Sample 4over Sample 3 may be attributed to the effect of the active materialliving in the gelled fluid, thereby having an extended viscosityreducing effects.

Example 5

This example illustrates the breaking characteristics of anotherembodiment of a microbial composition designated GUM-BAC™ available fromMicro-Bac International, Inc. of Round Rock, Tex. compared to controlsat a pH between 9.9 and 10.8 over an 11 day period of time. Themicrobial composition is either unencapsulated or encapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)of a 2% KCl aqueous solution prepared using San Antonio tap water. Theviscosity testing was carried out at a temperature of 150° F. and at apH between 10.2 and 10.4. The sample 1, designated Blank, was the gelledfluid itself, without additives, and served as a reference or control.The sample 2, designated Blank+0.05 gpt Biocide, was prepared as abovewith the addition of 0.05 gpt of a biocide. The sample 3, designatedBlank+5 gpt GUM-BAC™, was prepared as above with the addition of 5 gptof the microbial composition GUM-BAC™. The sample 4, designated Blank+5ppt encapsulated GUM-BAC™, was prepared as above with the addition of 5ppt an encapsulated composition of GUM-BAC™. The results of theviscosity testing is tabulated in Table 5 and shown graphically in FIG.5.

TABLE 5 Viscosity Reduction Results of a GUM-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) in a Tap Water Based, Gua GelledFluid @ 150° F. Sample 2 Sample 3 Sample 4 Control + Control + Control +Time of Sample 1 0.05 gpt 5 gpt 5 ppt Evaluation Control BiocideGUM-BAC ™ GUM-BAC ™^(†) 0 hours 49.0 49.0 49.0 50.0 2 Days 41.0 41.040.0 41.0 4 Days 39.0 38.1 38.9 38.3 8 Days 38.1 37.0 36.6 36.8 11 Days38.1 37.4 37.6 37.2 ^(†)encapsulated

Again, it can be seen from the data in Table 5 and in the plot of FIG. 5that at pH 10, the microbial compositions showed little improvement overthe control. Thus, the microbial compositions show some pH sensitivityevidencing higher activity as lower pH.

Example 6

This example illustrates the breaking characteristics of anotherembodiment of a microbial composition designated G GUM-BAC™ alsoavailable from Micro-Bac International, Inc. of Round Rock, Tex.compared to controls at pH 7 and pH 10. The microbial composition isunencapsulated.

Four samples were prepared for this viscosity breaking study. The fluidused in this example was a guar containing gelled fluid. The gelledfluid was formed by mixing 20 pounds of guar per thousand gallons (ppt)in a 2% KCl aqueous solution prepared using San Antonio tap water. Theviscosity testing was carried out at a temperature of 150° F. and at apH of 7.80 and 10.21. The sample 1, designated Blank @ pH7.80, was thegelled fluid itself at pH 7.80, without additives, and served as a pH7.80 reference or control. The sample 2 designated Blank+5 gpt GUM-BAC™,was prepared as above with the addition of 5 gpt of GUM-Bac also at pH7.19. The sample 3, designated Blank @ pH 10.21, was the gelled fluiditself at pH 10.21, without additives, and served as a pH 10.43reference or control. The sample 4, designated Blank+5 gpt GUM-BAC™, wasprepared as above with the addition of 5 gpt of GUM-BAC™ at pH 10.21.The results of the viscosity testing is tabulated in Table 6 and showngraphically in FIG. 6.

TABLE 6 Viscosity Reduction Results of a GUM-BAC ™ Microbial Composition(Non-Encapsulated and Encapsulated) @ 150° F. In tap Water and usingBiocide @ pH 7.8 and 10.21 Sample 2 Sample 4 Control + Control + Sample1 5 gpt Sample 3 5 ppt Time of Control GUM-BAC ™ Control GUM-BAC ™^(†)Evaluation @ pH 7.80 @ pH 7.80 @ pH 10.21 @ pH 10.21  0 hours 54.9 55.446.4 45.8 3 Days 7.6 8.3 9.8 9.6 5 Days 5.8 6.4 9.7 9.3 7 Days 3.8 5.99.7 9.0 ^(†)encapsulated

Again, it can be seen from the data in Table 6 and in the plot of FIG. 6that in the presence of a biocide (BioClear 200), the viscosity breakingcharacteristics of the microbial composition can be neutralized. Theabove data clearly shows that microbial composition, unencapsulated orencapsulated, can effectively break the viscosity of guar thickened fracfluids in a controlled manner. The data also suggests that bycontrolling the amount of the compositions in encapsulated form and theamount in unencapsulated form, one can control the rate and profile ofviscosity reduction in a guar gelled frac fluid. The data also suggeststhat an apparatus can be designed that would release the microbes in asudden form. Such apparatus can include an encapsulating coatingdesigned to breakdown after a specified exposure to a chemical, totemperature, to pressure, and/or to an aqueous environment. Theapparatus can also includes a capillary injection method for injectingthe active microbial into the formation at a specific time after fracfluid injection into the formation.

All references cited herein are incorporated by reference. Although theinvention has been disclosed with reference to its preferredembodiments, from reading this description those of skill in the art mayappreciate changes and modification that may be made which do not departfrom the scope and spirit of the invention as described above andclaimed hereafter.

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 15. An apparatusfor reducing viscosity of a gelled fluid, comprising: a capsulecontaining a viscosity reducing microbe disposed within the capsule,wherein the capsule is adapted to release the viscosity reducing microbeinto gelled fluid over time or in response to a change in a fluidproperty.
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 17. (canceled)
 18. (canceled)
 19. (canceled)20. (canceled)
 21. (canceled)
 22. The apparatus of claim 15, wherein thechange in the fluid property includes changing a temperature of thefluid, exposing the fluid to an aqueous fluid, changing a pH of thefluid, changing a pressure, exposing the fluid to shear, exposing thefluid to an additive designed to remove or destroy the encapsulatingagent, or a combination of some or all of these deencapsulatingcondition.
 23. The apparatus of claim 15, wherein the change in thefluid property comprises changing a temperature of the fluid to atemperature sufficient to remove or destroy the encapsulating agent. 24.The apparatus of claim 15, wherein the change in the fluid propertycomprises exposing the fluid to an aqueous fluid, where the aqueousfluid removes or destroys the encapsulating agent.
 25. The apparatus ofclaim 15, wherein the change in the fluid property comprises changing apH of the fluid to a pH sufficient to remove or destroy theencapsulating agent.
 26. The apparatus of claim 15, wherein the changein the fluid property comprises changing a pressure to a pressuresufficient to remove or destroy the encapsulating agent.
 27. Theapparatus of claim 15, wherein the change in the fluid propertycomprises exposing the fluid to shear, where the shear is sufficient toremove or destroy the encapsulating agent.
 28. The apparatus of claim15, wherein the change in the fluid property comprises exposing thefluid to an additive designed to remove or destroy the encapsulatingagent.
 29. An apparatus for reducing viscosity of a gelled fluid,comprising: an outer shell and an interior filled with a viscosityreducing microbe, where the outer shell is adapted to rupture inresponse to a change in a fluid property.
 30. The apparatus of claim 29,wherein the change in the fluid property includes changing a temperatureof the fluid, exposing the fluid to an aqueous fluid, changing a pH ofthe fluid, changing a pressure, exposing the fluid to shear, exposingthe fluid to an additive designed to remove or destroy the encapsulatingagent, or a combination of some or all of these deencapsulatingcondition.
 30. The apparatus of claim 29, wherein the change in thefluid property comprises changing a temperature of the fluid to atemperature sufficient to remove or destroy the encapsulating agent. 31.The apparatus of claim 29, wherein the change in the fluid propertycomprises exposing the fluid to an aqueous fluid, where the aqueousfluid removes or destroys the encapsulating agent.
 32. The apparatus ofclaim 29, wherein the change in the fluid property comprises changing apH of the fluid to a pH sufficient to remove or destroy theencapsulating agent.
 33. The apparatus of claim 29, wherein the changein the fluid property comprises changing a pressure to a pressuresufficient to remove or destroy the encapsulating agent.
 34. Theapparatus of claim 29, wherein the change in the fluid propertycomprises exposing the fluid to shear, where the shear is sufficient toremove or destroy the encapsulating agent.
 35. The apparatus of claim29, wherein the change in the fluid property comprises exposing thefluid to an additive designed to remove or destroy the encapsulatingagent.
 36. A fluid composition for wellbore operations, comprising: anaqueous fluid; a fluid thickener; and a capsule containing a viscosityreducing microbe, where the viscosity reducing microbe, once releasedinto the fluid, is adapted to degrade the fluid thickener upon contacttherewith and where the capsule is designed to release the microbe inresponse to a change in a fluid property.
 37. The composition of claim36, wherein the change in the fluid property includes changing atemperature of the fluid, exposing the fluid to an aqueous fluid,changing a pH of the fluid, changing a pressure, exposing the fluid toshear, exposing the fluid to an additive designed to remove or destroythe encapsulating agent, or a combination of some or all of thesedeencapsulating condition.
 37. The composition of claim 36, wherein thechange in the fluid property comprises changing a temperature of thefluid to a temperature sufficient to remove or destroy the encapsulatingagent.
 38. The composition of claim 36, wherein the change in the fluidproperty comprises exposing the fluid to an aqueous fluid, where theaqueous fluid removes or destroys the encapsulating agent.
 39. Thecomposition of claim 36, wherein the change in the fluid propertycomprises changing a pH of the fluid to a pH sufficient to remove ordestroy the encapsulating agent.
 40. The composition of claim 36,wherein the change in the fluid property comprises changing a pressureto a pressure sufficient to remove or destroy the encapsulating agent.41. The composition of claim 36, wherein the change in the fluidproperty comprises exposing the fluid to shear, where the shear issufficient to remove or destroy the encapsulating agent.
 42. Thecomposition of claim 36, wherein the change in the fluid propertycomprises exposing the fluid to an additive designed to remove ordestroy the encapsulating agent.